Wellbores are formed in subterranean formations for various purposes including, for example, the extraction of oil and gas from a subterranean formation and the extraction of geothermal heat from a subterranean formation. A wellbore may be formed in a subterranean formation using a drill bit, such as, for example, an earth-boring rotary drill bit. Different types of earth-boring rotary drill bits are known in the art, including, for example, fixed-cutter bits (which are often referred to in the art as “drag” bits), rolling-cutter bits (which are often referred to in the art as “rock” bits), impregnated bits (impregnated with diamonds or other superabrasive particles), and hybrid bits (which may include, for example, both fixed cutters and rolling cutters).
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. The drill string comprises a series of elongated tubular segments connected end-to-end that extends into the wellbore from the surface of the formation. When weight is applied to the drill string and consequently to the drill bit, the rotating bit engages the formation and proceeds to form a wellbore. The weight used to push the drill bit into and against the formation is often referred to as the “weight-on-bit” (WOB). As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the wellbore. A diameter of the wellbore formed by the drill bit may be defined by the cutting structures disposed at the largest outer diameter of the drill bit.
Different types of bits work more efficiently against formations with different physical properties. For example, so-called “impregnated” drag bits are used conventionally for drilling hard and/or abrasive rock formations, such as sandstones. Such conventional impregnated drill bits typically employ a cutting face comprising superabrasive cutting particles, such as natural or synthetic diamond grit, dispersed within and metallurgically and mechanically bonded to a matrix of wear-resistant material. As such a bit drills, the matrix and embedded diamond particles wear, cutting particles are lost as the matrix wears and new cutting particles are exposed. FIG. 1 is a perspective view of such a conventional impregnated drill bit 10 as known in the art. For clarity, the bit 10 is inverted from its normal face-down orientation during operation of the bit 10 while forming a wellbore in an earth formation. The bit 10 may have a longitudinal axis 12 representing a vertical axis, conventionally the centerline of a bit body 14, about which the bit 10 rotates in operation. The bit body 14 may comprise a shank 16 for connection to a drill string. The shank 16 may be coupled to a crown 18 of the bit 10. In some embodiments, the crown 18 may comprise a particulate-impregnated matrix material, which refers to a matrix material having abrasive particles or material including, but not limiting to, natural or synthetic diamond grit dispersed therein. The crown 18 may comprise a bit face surface 20 extending from the longitudinal axis 12 to a gage 22. A plurality of blades 24 may extend generally radially outwardly across the bit face surface 20. A plurality of fluid channels 26 may extend between and recessed from the blades 24. A plurality of nozzle ports for communicating drill fluid from an interior of the bit body 14 to the bit face surface 20 may be provided in one or more of the fluid channels 26. The plurality of blades 24 may comprise a plurality of discrete, post-like cutting structures 28 thereon.
The cutting structures 28 are mounted to or formed on the blades 24 such that at least a portion of the cutting structure 28 extends over the bit face surface 20. In other words, the cutting structures 28 are formed to at least partially extend over an outer surface 30 of the blades 24 such that the cutting structures 28 engage and cut formation material upon initial cutting action of the bit 10. Additionally, the cutting structures 28 are separated from each other to promote the flow of drilling fluid therearound for enhanced cooling and clearing of formation material.
As illustrated in FIG. 1, the cutting structures 28 comprise cylindrical posts having a generally round or circular transverse cross-section and having a substantially flat, outermost end 32 as disclosed, for example, in U.S. Pat. No. 6,510,906, entitled “Impregnated Bit with PDC Cutters in Cone Area,” issued Jan. 28, 2003. Alternatively, as known in the art, the cutting structure 28 may comprise other post-like structures having a variety of transverse cross-sections and outermost end shapes. For example, the cutting structures 28 may have a transverse cross-section that increases or tapers in cross-sectional area as the cutting structure is worn down, as disclosed in U.S. Pat. No. 9,243,458, entitled “Methods for Pre-sharpening Impregnated Cutting Structures for Bits, Resulting Cutting Structures and Drill Bits So Equipped,” issued Jan. 26, 2016. The outermost end 32 of the cutting structures 28 may be non-planar or arcuate having, for example, a saddle-shaped end as disclosed in U.S. Patent Pub. 2012/0080240, entitled “Diamond Impregnated Cutting Structures, Earth-boring Drill Bits and Other Tools Including Diamond Impregnated Cutting Structures, and Related Methods,” filed Oct. 5, 2011, now U.S. Pat. No. 9,567,807, issued Feb. 14, 2017.
FIG. 2 illustrates a bottom view of an exemplary embodiment of a conventional coring bit 50. The bit 50 includes a bit body 52 having a bit face surface 54. A central opening, or throat 56, extends into the bit body 52 and is adapted to receive a core (not shown) being cut. A plurality of blades 58 may be disposed on the face surface 54 and may extend radially outward toward a gage 60 of the bit body 52 from a longitudinal axis 62 of the bit 50. The longitudinal axis 62 extends into the page in the bottom view of FIG. 2 and represents a vertical axis, conventionally the centerline of the bit body 52, about which the coring bit 50 rotates in operation. A plurality of fluid channels 64 extend radially between and recessed from the blades 58. A plurality of cutting structures 68 are attached to the blades 58.
In operation, the coring bit 50 is rotated about the longitudinal axis 62 and is used to cut a cylindrical core from the earth formation and to transport the core to the surface for analysis. The cutting structures 68 extend at least partially over an outer surface 70 of the blades 58 such that, upon initial cutting action of the coring bit 50, the cutting structures 68 engage and cut formation material. The cutting structures 68, like the cutting structures 28 of FIG. 1, comprise cylindrical posts as disclosed in U.S. Pat. No. 7,730,976, entitled “Impregnated Rotary Drag Bit and Related Methods,” issued Jun. 8, 2010. The core of formation material cut by the bit 50 and the cutting structures 68 is received in the throat 56 and transported to the surface.